1. Field of the Invention
The present invention relates to an apparatus and reburn method for in-furnace reduction of nitrogen oxide emissions in flue gas.
2. Description of the Prior Art
During combustion of fuels with fixed nitrogen such as coal, oxygen from the air may combine with the nitrogen to produce nitrogen oxides (NO.sub.x). At sufficiently high temperatures, oxygen reacts directly with atmospheric nitrogen to form NO.sub.x. Emission of nitrogen oxide is regarded as undesirable because the presence of nitrogen oxide in furnace flue gas (along with sulfur dioxides) causes the condensed gases to become corrosive and acidic. There are numerous government regulations which limit the amount of nitrogen oxide which may be emitted from a combustion furnace. Titles I and IV of the Clean Air Act as amended in 1990 ("the Clean Air Act") require significant NO.sub.x reduction from large power plants. Title I of the Clean Air Act focuses on the problem of ozone non-attainment. Ozone is formed as a result of photochemical reactions between nitrogen oxides emitted from central power generating stations, vehicles and other stationary sources, and volatile organic compounds. Ozone is harmful to human health. Consequently, in many urban areas the Title I NO.sub.x controls are more stringent than the Title IV limits. Thus, there is a need for apparatus and processes which reduce the nitrogen oxide emissions in furnace flue gas.
Commercially available techniques to reduce the nitrogen oxide emissions in furnace flue gas are low NO.sub.x burners, selective non-catalytic NO.sub.x reduction (SNCR), selective catalytic reduction (SCR) and reburning. Currently, retrofitting boilers with low NO.sub.x burners is the most economic route to comply with Title IV requirements of the Clean Air Act. However, low NO.sub.x burners cannot reduce NO.sub.x emissions to levels required by Title I of the Clean Air Act. As a consequence electric utilities are faced with the option of adding SNCR or reburning to the boiler. In addition, there are cyclone boilers for which there is no low NO.sub.x burner technology. SNCR and reburning are the two options for cyclone boilers.
The reburning process is also known as in-furnace nitrogen oxide reduction or fuel staging. The standard reburning process has been described in several patents and publications. See for example, "Enhancing the Use of Coals by Gas Reburning-Sorbent Injection," submitted by the Energy and Environmental Research Corporation (EER) at the First Industry Panel Meeting, Pittsburgh, Pa., Mar. 15, 1988; "GR-SI Process Design Studies for Hennepin Unit #1--Project Review," Energy and Environmental Research Corporation (EER), submitted at the Project Review Meeting on Jun. 15-16, 1988; "Reduction of Sulfur Trioxide and Nitrogen Oxides by Secondary Fuel Injection," Wendt, et al.; Fourteenth Symposium (International) on Combustion, The Combustion Institute, 1973, pp. 897-904. "Mitsubishi `MACT` In-Furnace NO.sub.x Removal Process for Steam Generator," Sakai, et al.; published at the U.S.-Japan NO.sub.x Information Exchange, Tokyo, Japan, May 25-30, 1981.
In reburning a fraction of the total thermal input is injected above the primary flame zone in the form of a hydrocarbon fuel such as coal, oil, or gas. A reburn zone stoichiometry of 0.90 (10% excess fuel) is considered optimum for NO.sub.x control. Thus, the amount of reburn fuel can be calculated from the primary zone excess air. Under typical boiler conditions a reburn fuel input in the range 15% to 25% is sufficient to form a fuel-rich zone. The reburn fuel is injected at high temperatures in order to promote reactions under the overall fuel rich stoichiometry. Typical flue gas temperatures at the injection location are above 2600.degree. F. Completion air is added above the reburn zone in order to burn off the unburnt hydrocarbons and carbon monoxide (CO). In addition to the above specifications the prior art on standard reburn teaches the benefits of rapid and complete dispersion of the reburn fuel in flue gas. Thus, flue gas recirculation (FGR) has been used to promote mixing in all standard reburn demonstrations. Standard reburn technology requires a tall furnace to set up a fuel rich zone followed by a lean burn out zone. Many furnaces do not have the volumes required for retrofitting this technology.
U.S. Pat. No. 4,810,186 titled, Apparatus For Burning Fuels While Reducing the Nitrogen Level, describes a standard reburn process for reducing NO.sub.x in tangentially fired furnaces. The taught process has a fuel rich zone followed by a burn out zone, and is limited to tangentially fired boilers. The patent describes tangentially-fired equipment having a plurality of main burners oriented in conformity with a burning circle, a plurality of reduction burners, and a plurality of burn-out or completion air nozzles disposed above the reduction burners. Thus, there are disposed in any burner plane, i.e. in a vertical plane, one above the other a main burner, a reduction burner, and a burn-out nozzle. In such a combustion configuration the fuel, air and burnt gas from each burner moves upwards in a helical trajectory, and "when the reduction burner is placed above the main burners there is no assurance that the reburning fuel will contact the NO.sub.x that is formed below." The authors show a helical path from only a single burner to emphasize their point. In actuality there are anywhere from 12 to 28 or more burners in a tangentially fired furnace and when the helical paths of flue gas from all the burners are considered it is clear that the reducing fuel from the reducing burners will contact the NO.sub.x from below. The patent states that the reburn fuel injectors be located in such a manner so as to maximize the contact between the NO.sub.x and the reburn fuel. However, it teaches that the reducing fuel injectors be placed along side the primary fuel injectors which is a very ineffective method for NO.sub.x control in coal fired furnaces.
The method of the '186 patent suffers from a single major drawback. It teaches reburn fuel injection at extremely high temperatures in the firing zone which is not ideal for NO.sub.x reduction using natural gas. Gas injection and combustion in the primary firing zone has little impact on NO.sub.x and may actually increase NO.sub.x formation. Gas injection in the primary firing zone of pulverized coal fired furnaces is known as co-firing. There are data from several gas/coal co-firing projects showing little if any reduction in NO.sub.x when natural gas is fired in this manner. The little NO.sub.x reduction can be explained by the decrease in the overall oxygen and by the decrease in the coal and coal bound nitrogen flow rate. The primary reason for the small NO.sub.x reduction is that gas co-injection delays coal combustion and conversion of coal nitrogen into nitrogen because gas burns much faster than coal.
Full scale demonstrations of standard natural gas reburning with FGR and completion air have shown up to 65% NO.sub.x reduction under the high temperature fuel rich conditions in several cyclone, wall, and tangentially fired boilers. Standard natural gas reburn as practiced today is expensive because of the capital and operating expense for FGR and completion air. In addition the need to create a fuel rich zone and the use of greater than 10% gas makes standard gas reburn uneconomical for most coal fired furnaces. Coal has also been used as a reburn fuel because it is much less expensive than natural gas. A finer coal grind than the typical utility grind used in the primary burners is required in order to improve coal devolatilization and promote char burnout in the upper furnace. However, coal has inherent bound nitrogen which can get oxidized to NO.sub.x during the completion process. For this reason, the use of coal as a reburn fuel is limited to initial NO.sub.x concentrations greater than 300 ppm. This effectively precludes the use of coal reburn in many furnaces equipped with low NO.sub.x burners.
Another chemical reagent based NO.sub.x reduction technique is the selective non-catalytic reduction (SNCR) process. In this process NO is reduced to nitrogen (N.sub.2) by injecting any one of the following compounds: ammonia (NH.sub.3), urea, or cyanuric acid into the furnace. All these compounds either directly (as in the case of ammonia deNO.sub.x process) or indirectly form amine radicals (NH, NH.sub.2) which react subsequently with NO.sub.x in the flue gas to produce N.sub.2. The process is called selective because the chemical reagents react selectively with NO.sub.x. Thus, small amounts of the ammonia, urea, or cyanuric acid are required. For ammonia injection a concentration only 25% greater than the flue gas NO.sub.x concentration may be required for significant NO.sub.x reduction. Presence of small quantities of oxygen normally present in the flue gas are beneficial for starting the decomposition of the chemical additives. The relevant nitrogen chemistry in the SNCR processes is present in reburn as well, albeit to a lesser extent because the amine radical concentrations are lower. The SNCR chemistry is peculiar that it occurs in a narrow temperature window, from 1700.degree. F. to 1900.degree. F. At higher temperatures, the reagents may be oxidized to NO.sub.x under typical flue gas oxygen concentrations. At lower temperatures the reactions do not occur to a significant extent and reagent leakage or slip (NH.sub.3, urea, cyanuric acid) can occur. The narrow process temperature window is a major drawback of the SNCR process, and results in lower than theoretical NO.sub.x reductions because of the difficulty in maintaining uniform spatial optimum injection conditions in boilers which operate at varying loads because of electric demand and dispatch requirements. Incomplete reagent mixing and dispersion also lowers the efficiency. Reagent leakage can cause ammonium sulfate particulate formation and deposits on downstream equipment. Emission of nitrous oxide (N.sub.2 O), a greenhouse gas and an intermediate product, from some SNCR processes is also of concern.
Consequently, there is a need for a combustion apparatus and process which will reduce nitrogen oxide emissions in flue gas and which can be readily used in existing furnaces. An improved reburn technology has been patented by Breen et al. in a series of patents (U.S. Pat. Nos. 4,779,545; 5,078,064 and 5,181,475) The new technology, called reducing eddy after burn (REAB), differs from the standard reburn in the following respects. Breen et al. inject raw natural gas or a stream of mostly natural gas as fuel eddies (as generated by a turbulent fuel jet, vortex rings or diffusive devices) whereas standard reburn uses turbulent gas jets with flue gas recirculation. REAB does not require and preferably does not use flue gas recirculation. NO.sub.x reduction occurs in locally fuel rich zones, such as fuel eddies and vortex rings, in contrast to a globally fuel rich zone. Slow or controlled mixing of natural gas with flue gas is required, in contrast to rapid mixing in standard reburn. Natural gas is injected at lower temperatures, from 1800.degree. F. to 2400.degree. F., consistent with chemical kinetics. Operating at lower temperatures enables potentially higher NO.sub.x reductions because the thermodynamic equilibrium NO.sub.x is less than 125 ppm at 1800.degree. F. In the REAB process there is no need for completion air addition since the furnace is over all fuel lean. Mix out and oxidation of the unburnt hydrocarbons and CO from the local fuel rich zones occurs due to the existing turbulence in the flow. REAB is less expensive than standard reburn because it uses less natural gas, does not require flue gas recirculation, and does not require completion air.
Recently we filed a U.S. patent application Ser. No. 08/417,916 describing an improvement of the REAB technology, called the controlled mixing upper furnace NO.sub.x reduction technology (CM/UFNR). In CM/UFNR a combustible fluid such as natural gas is introduced into the upper furnace through gas fired gas jet injectors. In these injectors a small portion of the natural gas is combusted with air (or vitiated air); the resultant gas is mixed with the majority of the natural gas; and the mixture is then injected into the furnace as a very fuel-rich jet. The combustion of a small fraction of natural gas is used to modulate the momentum of the gas jet and consequently its mixing characteristics. The combustion increases the temperature and velocity of the resultant jet, results in early hydrocarbon radical formation and thus accelerates the rate of the reburn chemistry. The injection of these jets into the furnace results in a complex mixing process which can be described by the formation and shedding of fuel rich eddies from the main jet. In these eddies the nitrogen oxide formed in the coal burner will be reduced to ammonia, cyanide-like fragments, and N.sub.2. As these eddies decay and mix with the flue gas, they experience an oxidizing environment, where the ammonia like compounds react with more NO.sub.x to form nitrogen. As mentioned above, these selective "thermal deNO.sub.x " reactions occur in a narrow temperature range of 1700.degree. F. to 1900.degree. F. Therefore, the gas fired gas jets are designed and located in such a manner so as to take advantage of the thermal deNO.sub.x chemistry. Thus, the nitrogen oxide in the flue gas is reduced at the same time that the combustion of natural gas is completed. In standard reburn a significant portion of the hydrogen cyanide (HCN) and amine (NH.sub.i) species formed in the fuel rich zone is oxidized to NO because the completion air is added at gas temperatures greater than 2200.degree. F.
The REAB and CM/UFNR technologies are well suited for retrofitting existing coal furnaces. Because the process relies on controlled mixing to provide fuel-rich and fuel-lean environments, there is no need for an air addition stage. Because gas burns more rapidly at a lower temperature than coal, the fuel can be introduced at a higher elevation and lower temperature in the furnace. This lower temperature acts to reduce the equilibrium level of nitrogen oxide in the flue gas and, hence, increases the potential nitrogen oxide reduction. The cost of reducing NO.sub.x is decreased because duct work is not necessary for injection of completion air or recirculated flue gas, and less natural gas is used. Therefore, both capital and operating costs are lower than in standard reburn. While the REAB and CM/UFNR processes give a 40-60% reduction in NO.sub.x using 7-10% natural gas, it is clear that there is a need for the spatial injection process described below.